Method of formulating and using a drilling mud with fragile gels

ABSTRACT

A method for drilling, running casing in, and/or cementing a borehole in a subterranean formation without significant loss of drilling fluid is disclosed, as well as compositions for use in such method. The method employs a drilling fluid comprising a fragile gel or having fragile gel behavior and providing superior oil mud rheology and overall performance. The fluid is especially advantageous for use in deep water wells because the fluid exhibits minimal difference between downhole equivalent circulating density and surface density notwithstanding differences in drilling or penetration rates. When an ester and isomerized olefin blend is used for the base of the fluid, the fluid makes an environmentally acceptable and regulatory compliant invert emulsion drilling fluid. The fluid preferably contains no organophilic clays.

RELATED APPLICATIONS

This application is a division of U.S. patent application Ser. No.10/933,560, pending, which is a continuation of U.S. patent applicationSer. No. 10/175,272, filed Jun. 19, 2002, now U.S. Pat. No. 6,887,832,which is a continuation-in-part of U.S. patent application Ser. No.09/929,465, filed Aug. 14, 2001, now abandoned, and acontinuation-in-part of International Patent Application Nos.PCT/US00/35609 and PCT/US00/35610, both filed Dec. 29, 2000, under thePatent Cooperation Treaty, and now both pending in national phase in theUnited States respectively as U.S. patent application Ser. Nos.10/432,787 and 10/432,786.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to compositions and methods for drilling,cementing and casing boreholes in subterranean formations, particularlyhydrocarbon bearing formations. More particularly, the present inventionrelates to oil or synthetic fluid based drilling fluids and fluidscomprising invert emulsions, such as, for example, fluids using esters,which combine high ecological compatibility with good stability andperformance properties.

2. Description of Relevant Art

A drilling fluid or mud is a specially designed fluid that is circulatedthrough a wellbore as the wellbore is being drilled to facilitate thedrilling operation. The various functions of a drilling fluid includeremoving drill cuttings from the wellbore, cooling and lubricating thedrill bit, aiding in support of the drill pipe and drill bit, andproviding a hydrostatic head to maintain the integrity of the wellborewalls and prevent well blowouts. Specific drilling fluid systems areselected to optimize a drilling operation in accordance with thecharacteristics of a particular geological formation.

Oil or synthetic fluid-based muds are normally used to drill swelling orsloughing shales, salt, gypsum, anhydrite or other evaporite formations,hydrogen sulfide-containing formations, and hot (greater than about 300degrees Fahrenheit) holes, but may be used in other holes penetrating asubterranean formation as well. Unless indicated otherwise, the terms“oil mud” or “oil-based mud or drilling fluid” shall be understood toinclude synthetic oils or other synthetic fluids as well as natural ortraditional oils, and such oils shall be understood to comprise invertemulsions.

Oil-based muds used in drilling typically comprise: a base oil (orsynthetic fluid) comprising the external phase of an invert emulsion; asaline, aqueous solution (typically a solution comprising about 30%calcium chloride) comprising the internal phase of the invert emulsion;emulsifiers at the interface of the internal and external phases; andother agents or additives for suspension, weight or density,oil-wetting, fluid loss or filtration control, and rheology control.Such additives commonly include organophilic clays and organophiliclignites. See H. C. H. Darley and George R. Gray, Composition andProperties of Drilling and Completion Fluids 66-67, 561-562 (5^(th) ed.1988). An oil-based or invert emulsion-based drilling fluid may commonlycomprise between about 50:50 to about 95:5 by volume oil phase to waterphase. An all oil mud simply comprises 100% oil by volume; that is,there is no aqueous internal phase.

Invert emulsion-based muds or drilling fluids comprise a key segment ofthe drilling fluids industry. However, increasingly invertemulsion-based drilling fluids have been subjected to greaterenvironmental restrictions and performance and cost demands. There isconsequently an increasing need and industry-wide interest in newdrilling fluids that provide improved performance while still affordingenvironmental acceptance.

SUMMARY OF THE INVENTION

The present invention provides a fluid and a method for drillingboreholes or wellbores in subterranean formations with reduced loss ofdrilling fluids or muds into the formation. This advantage of theinvention is effected by formulating, providing or using a drillingfluid that forms a “fragile gel.” A “gel” may be defined a number ofways. One definition indicates that a “gel” is a generally colloidalsuspension or a mixture of microscopic water particles (and anyhydrophilic additives) approximately uniformly dispersed through the oil(and any hydrophobic additives), such that the fluid or gel has agenerally homogeneous gelatinous consistency. Another definition statesthat a “gel” is a colloid in a more solid form than a “sol” and definesa “sol” as a fluid colloidal system, especially one in which thecontinuous phase is a liquid. Still another definition provides that a“gel” is a colloid in which the disperse phase has combined with thecontinuous phase to produce a viscous jelly-like product. A gel has astructure that is continually building. If the yield stress of a fluidincreases over time, the fluid has gels. Yield stress is the stressrequired to be exerted to initiate deformation.

A “fragile gel” as used herein is a “gel” that is easily disrupted orthinned, and that liquifies or becomes less gel-like and moreliquid-like under stress, such as caused by moving the fluid, but whichquickly returns to a gel when the movement or other stress is alleviatedor removed, such as when circulation of the fluid is stopped, as forexample when drilling is stopped. The “fragileness” of the “fragilegels” of the present invention contributes to the unique and surprisingbehavior and advantages of the present invention. The gels are so“fragile” that it is believed that they may be disrupted by a merepressure wave or a compression wave during drilling. They seem to breakinstantaneously when disturbed, reversing from a gel back into a liquidform with minimum pressure, force and time and with less pressure, forceand time than known to be required to convert prior art fluids from agel-like state into a flowable state.

When drilling is stopped while using a drilling fluid of the presentinvention, and consequently the stresses or forces associated withdrilling are substantially reduced or removed, the drilling fluid formsa gel structure that allows it to suspend drill cuttings and weightingmaterials for delivery to the well surface. The drilling fluid of theinvention suspends drill cuttings through its gel or gel-likecharacteristics, without need for organophilic clays to add viscosity tothe fluid. As a result, sag problems do not occur. Nevertheless, whendrilling is resumed, the fragile gel is so easily and instantlyconverted back into a liquid or flowable state that no initialappreciable or noticeable pressure spike is observed withpressure-while-drilling (PWD) equipment or instruments. In contrast,such pressure spikes are commonly or normally seen when using prior artfluids.

Further, the drilling fluid of the invention generally maintainsconsistently low values for the difference in its surface density andits equivalent density downhole during drilling operationsnotwithstanding variations in the rate of drilling or penetration intothe subterranean formation and notwithstanding other downhole stresseson the fluid. The fragile gels of the invention may be visco-elastic,contributing to their unique behavior and to the advantages of theinvention.

The drilling fluid of the invention responds quickly to the addition ofthinners, with thinning of the fluid occurring soon after the thinnersare added, without need for multiple circulations of the fluid with thethinners additive or additives in the wellbore to show the effect of theaddition of the thinners. The drilling fluid of the invention alsoyields flatter profiles between cold water and downhole rheologies,making the fluid advantageous for use in deep water wells. That is, thefluid may be thinned at cold temperatures without causing the fluid tobe comparably thinned at higher temperatures. As used herein, the terms“deep water” with respect to wells and “higher” and “lower” with respectto temperature are relative terms understood by one skilled in the artof the oil and gas industry. However, generally, as used herein, “deepwater wells” refers to any wells at water depths greater than about 1500feet deep, “higher temperatures” means temperatures over about 120degrees Fahrenheit and “lower temperatures” means temperatures at about40 to about 60 degrees Fahrenheit. Rheology of a drilling fluid istypically measured at about 120 or about 150 degrees Fahrenheit.

A method for preparing and using a drilling fluid of the invention isalso provided by the invention. In the method, an invert emulsiondrilling fluid is obtained or prepared that forms fragile gels or thathas fragile gel behavior, preferably without the addition oforganophilic clays or organophilic lignites, and that has as its base aninvert emulsion composition. An example of a suitable base is a blend ofesters with isomerized, or internal, olefins (“the ester blend”) asdescribed in U.S. patent application Ser. No. 09/929,465, of JeffKirsner (co-inventor of the present invention), Kenneth W. Pober andRobert W. Pike, filed Aug. 14, 2001, entitled “Blends of Esters withIsomerized Olefins and Other Hydrocarbons as Base Oils for InvertEmulsion Oil Muds, incorporated herein by reference.

Drilling fluids of the present invention prepared with such ester blendsprovide an invert emulsion drilling fluid having significant benefits interms of environmental acceptance or regulatory compliance while alsoimproving oil mud rheology and overall oil mud performance. The estersin the blend may be any quantity, but preferably should comprise atleast about 10 weight percent to about 99 weight percent of the blendand the olefins should preferably comprise about 1 weight percent toabout 99 weight percent of the blend. The esters of the blend arepreferably comprised of fatty acids and alcohols and most preferablyabout C₆ to about C₁₄ fatty acids and 2-ethyl hexanol. Esters made otherways than with fatty acids and alcohols, such as for example, estersmade from olefins combined with either fatty acids or alcohols, are alsobelieved effective.

Further, the invert emulsion drilling fluid has added to or mixed withit other fluids or materials needed to comprise a complete drillingfluid. Such materials may include thinners or rheology control additivesfor example. However, preferably no organophilic clays are added to thedrilling fluid for use in the invention. Characterization of thedrilling fluid herein as “clayless” shall be understood to mean lackingorganophilic clays. Although omission of organophilic clays is a radicaldeparture from traditional teachings respecting preparation of drillingfluids, this omission of organophilic clays in the present inventionallows the drilling fluid to have greater tolerance to drill solids(i.e., the properties of the fluid are not readily altered by the drillsolids or cuttings) and is believed (without desiring to be limited bytheory) to contribute to the fluid's superior properties in use as adrilling fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1(a), 1(b) and 1(c) provide three graphs showing field datacomparing mud losses incurred during drilling, running casing andcementing with a prior art isomerized olefin fluid and with a fluid ofthe present invention. FIG. 1(a) shows the total downhole losses; FIG.1(b) shows the barrels lost per barrel of hole drilled; and FIG. 1(c)shows the barrels lost per foot.

FIG. 2 is a graph comparing mud loss incurred running casing andcementing in seven boreholes at various depths, where the mud used inthe first three holes was a prior art isomerized olefin fluid and themud used in the last four holes was a fluid of the present invention.

FIG. 3 is a graph indicating gel formation in fluids of the presentinvention and their response when disrupted compared to some prior artisomerized olefin fluids.

FIG. 4 is a graph comparing the relaxation rates of various prior artdrilling fluids and fluids of the present invention.

FIG. 5(a) is a graph comparing the differences in well surface densityand the equivalent circulating density for a prior art isomerized olefinfluid and for the fluid of the invention in two comparable wells. FIG.5(b) shows the rate of penetration in the wells at the time the densitymeasurements for FIG. 5(a) were being taken.

FIG. 6 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention with aflowrate of 704 to 811 gallons per minute in a 12¼ inch borehole drilledfrom 9,192 ft to 13,510 ft in deep water and including rate ofpenetration.

FIG. 7 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention with aflowrate of 158 to 174 gallons per minute in a 6½ inch borehole drilledfrom 12,306 ft to 13,992 ft and including rate of penetration.

FIG. 8 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention atvarying drilling rates from 4,672 ft to 12,250 ft, and a flowrate of 522to 586 gallons per minute in a 9⅞″ borehole.

FIG. 9(a) is a bar graph comparing the yield point of two densities of afluid of the invention at standard testing temperatures of 40 and 120degrees Fahrenheit. FIGS. 9(b) and (c) are graphs of the Fann instrumentdial readings for these same two densities of a fluid of the inventionover a range of shear rates at standard testing temperatures of 40 and120 degrees Fahrenheit.

FIG. 10 is a graph comparing the viscosity of various known invertemulsion bases for drilling fluids with the invert emulsion base for adrilling fluid of the present invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention has been tested in the field and the field datademonstrates the advantageous performance of the fluid composition ofthe invention and the method of using it. As illustrated in FIGS. 1(a),(b), (c), and 2, the present invention provides an invert emulsiondrilling fluid that may be used in drilling boreholes or wellbores insubterranean formations, and in other drilling operations in suchformations (such as in casing and cementing wells), without significantloss of drilling fluid when compared to drilling operations with priorart fluids.

FIGS. 1(a), (b), and (c) show three graphs comparing the actual fluidloss experienced in drilling 10 wells in the same subterraneanformation. In nine of the wells, an isomerized olefin based fluid (inthis case, tradename PETROFREE® SF available from Halliburton EnergyServices, Inc. in Houston, Tex.), viewed as an industry “standard” forfull compliance with current environmental regulations, was used. In onewell, an ACCOLADE™ system, a fluid having the features orcharacteristics of the invention and commercially available fromHalliburton Energy Services, Inc. in Houston, Tex. (and also fullycomplying with current environmental regulations) was used. The holedrilled with an ACCOLADE™ system was 12.25 inches in diameter. The holesdrilled with the “standard” PETROFREE® SF fluid were about 12 inches indiameter with the exception of two sidetrack holes that were about 8.5inches in diameter. FIG. 1(a) shows the total number of barrels of fluidlost in drilling, running, casing and cementing the holes. FIG. 1(b)shows the total number of barrels of fluid lost per barrel of holedrilled. FIG. 1(c) shows the total number of barrels of fluid lost perfoot of well drilled, cased or cemented. For each of these wells graphedin these FIGS. 1(a), (b) and (c), the drilling fluid (or mud) lost whenusing a fluid of the invention was remarkably lower than when using theprior art fluid.

FIG. 2 compares the loss of mud with the two drilling fluids in runningcasing and cementing at different well depths in the same subterraneanformation. The prior art isomerized olefin based fluid was used in thefirst three wells shown on the bar chart and a fluid of the presentinvention was used in the next four wells shown on the bar chart. Again,the reduction in loss of fluid when using the fluid of the presentinvention was remarkable.

The significant reduction in mud loss seen with the present invention isbelieved to be due at least in substantial part to the fragile gelbehavior of the fluid of the present invention and to the chemicalstructure of the fluid that contributes to, causes, or results in thatfragile gel behavior. According to the present invention, fluids havingfragile gels or fragile gel behavior provide significant reduction inmud loss during drilling (and casing and cementing) operations whencompared to mud losses incurred with other drilling fluids that do nothave fragile gel behavior. Without wishing to be limited by theory, itis believed, for example, that the structure of the drilling fluids ofthe invention, that is, the fragile gel structure, contributing to thefragile gel behavior results in lower surge and swab pressure whilerunning casing which in turn results in lower mud loss during suchcasing operations. Thus, according to the method of the invention,drilling fluid loss may be reduced by employing a drilling fluid indrilling operations that is formulated to comprise fragile gels or toexhibit fragile gel behavior. As used herein, the term “drillingoperations” shall mean drilling, running casing and/or cementing unlessindicated otherwise.

FIG. 3 represents in graphical form data indicating gel formation insamples of two different weight (12.65 and 15.6 ppg) ACCOLADE® fluids ofthe present invention and two comparably weighted (12.1 and 15.6 ppg)prior art invert emulsion fluids (tradename PETROFREE® SF) at 120degrees Fahrenheit. When the fluids are at rest or static (as whendrilling has stopped in the wellbore), the curves are flat or relativelyflat (see area at about 50-65 minutes elapsed time for example). Whenshear stress is resumed (as in drilling), the curves move up straightvertically or generally vertically (see area at about 68 to about 80elapsed minutes for example), with the height of the curve beingproportional to the amount of gel formed—the higher the curve the moregel built up. The curves then fall down and level out or begin to levelout, with the faster rate at which the horizontal line forms (and thecloser the horizontal line approximates true horizontal) indicating thelesser resistance of the fluid to the stress and the lower the pressurerequired to move the fluid.

FIG. 3 indicates superior response and performance by the drillingfluids of the present invention. Not only do the fluids of the presentinvention build up more gel when at rest, which enables the fluids ofthe invention to better maintain weight materials and drill cuttings insuspension when at rest—a time prior art fluids are more likely to havedifficulty suspending such solid materials—but the fluids of the presentinvention nevertheless surprisingly provide less resistance to thesheer, which will result in lower ECDs as will be discussed furtherbelow.

FIG. 4 provides data further showing the gel or gel-like behavior of thefluids of the present invention. FIG. 4 is a graph of the relaxationrates of various drilling fluids, including fluids of the presentinvention and prior art isomerized olefin based fluids. In the test,conducted at 120 degrees Fahrenheit, the fluids are exposed to stressand then the stress is removed. The time required for the fluids torelax or to return to their pre-stressed state is recorded. The curvesfor the fluids of the invention seem to level out over time whereas theprior art fluids continue to decline. The leveling out of the curves arebelieved to indicate that the fluids are returning to a true gel orgel-like structure.

The significant reduction in mud loss seen with the present invention isalso believed to be due in substantial part to the suspectedviscoelasticity of the fluid of the present invention. Suchviscoelasticity, along with the fragile gel behavior, is believed toenable the fluid of the invention to minimize the difference in itsdensity at the surface and its equivalent circulating density downhole.This difference in a drilling fluid's measured surface density at thewell head and the drilling fluid's equivalent circulating densitydownhole (as typically measured during drilling by downholepressure-while-drilling (PWD) equipment) is often called “ECD” in theindustry. Low “ECDs”, that is, a minimal difference in surface anddownhole equivalent circulating densities, is critical in drilling deepwater wells and other wells where the differences in subterraneanformation pore pressures and fracture gradients are small.

Table 1 below and FIG. 5(a) showing the Table 1 data in graph formillustrate the consistently stable and relatively minimal difference inequivalent circulating density and actual mud weight or well surfacedensity for the fluids of the invention. This minimal difference isfurther illustrated in FIG. 5(a) and in Table 1 by showing theequivalent circulating density downhole for a commercially availableisomerized olefin drilling fluid in comparison to the drilling fluid ofthe present invention. Both fluids had the same well surface density.The difference in equivalent circulating density and well surfacedensity for the prior art fluid however was consistently greater thansuch difference for the fluid of the invention. FIG. 5(b) provides therates of penetration or drilling rates at the time the measurementsgraphed in FIG. 5(a) were made. FIG. 5(b) indicates that the fluid ofthe invention provided its superior performance—low ECDs—at surprisinglyfaster drilling rates, making its performance even more impressive, asfaster drilling rates tend to increase ECDs with prior art fluids. TABLE1 Comparison of Equivalent Circulating Densities PWD Data PWD DataIsomerized Olefin ACCOLADE ™ System based fluid pump rate: 934 gpm MudWeight pump rate: 936 gpm DEPTH BIT: 12.25″ At well surface BIT: 12.25″(in feet) (ppg) (ppg) (ppg)  10600 12.29 12.0 12.51  10704 12.37 12.012.53  10798 12.52 12.0 12.72 10,899 12.50 12.2 12.70 11,001 12.50 12.212.64 11,105 12.52 12.2 12.70 11,200 12.50 12.2 12.69 11,301 12.55 12.212.70 11,400 12.55 12.2 12.71 11,500 12.59 12.2 12.77 11,604 12.59 12.212.79 11,700 12.57 12.2 12.79 11,802 12.60 12.2 12.79 11,902 12.62 12.212.81 12,000 12.64 12.2 12.83 12,101 12.77 12.2 12.99 12,200 12.77 12.312.99 12,301 12.76 12.3 13.01

FIG. 6 graphs the equivalent circulating density of an ACCOLADE™ system,as measured downhole during drilling of a 12¼ inch borehole from 9,192feet to 13,510 feet in deepwater (4,900 feet), pumping at 704 to 811gallons per minute, and compares it to the fluid's surface density. Rateof penetration (“ROP”) (or drilling rate) is also shown. This datafurther shows the consistently low and stable ECDs for the fluid,notwithstanding differences in the drilling rate and consequently thedifferences in stresses on the fluid.

FIG. 7 similarly graphs the equivalent circulating density of anACCOLADE™ system, as measured downhole during drilling of a 6½ inchborehole from 12,306 feet to 13,992 feet, pumping at 158 to 174 gallonsper minute in deepwater, and compares it to the fluid's surface density.Rate of penetration (or drilling rate) is also shown. Despite therelatively erratic drilling rate for this well, the ECDs for thedrilling fluid were minimal, consistent, and stable. Comparing FIG. 7 toFIG. 6 shows that despite the narrower borehole in FIG. 6 (6½ inchescompared to the 12¼ inch borehole for which data is shown in FIG. 6),which would provide greater stress on the fluid, the fluid performanceis effectively the same.

FIG. 8 graphs the equivalent circulating density of an ACCOLADE™ system,as measured-downhole during drilling of a 9⅞ inch borehole from 4,672feet to 12,250 feet in deepwater, pumping at 522 to 585 gallons perminute, and compares it to the surface density of the fluid and the rateof penetration (“ROP”) (or drilling rate). The drilling fluid providedlow, consistent ECDs even at the higher drilling rates.

The present invention also provides a drilling fluid with a relativelyflat rheological profile. Table 2 provides example rheological data fora drilling fluid of the invention comprising 14.6 pounds per gallon(“ppg”) of an ACCOLADE™ system. TABLE 2 ACCOLADE ™ System DownholeProperties FANN 75 Rheology 14.6 lb/gal ACCOLADE ™ System Temp. (° F.)120 40 40 40 80 210 230 250 270 Pressure 0 0 3400 6400 8350 15467 1646617541 18588 600 rpm 67 171 265 325 202 106 98 89 82 300 rpm 39 90 148185 114 63 58 52 48 200 rpm 30 64 107 133 80 49 45 40 37 100 rpm 19 3964 78 47 32 30 27 25 6 rpm 6 6 10 11 11 8 9 8 8 3 rpm 5 6 10 11 11 8 9 88 Plastic 32 81 117 140 88 43 40 37 34 Viscosity (cP) Yield Point 7 9 3145 26 20 18 15 14 (lb/100 ft²) N 0.837 0.948 0.869 0.845 0.906 0.7990.822 0.855 0.854 K 0.198 0.245 0.656 0.945 0.383 0.407 0.317 0.226 0.21Tau 0 4.68 6.07 8.29 8.12 9.68 7.45 8.21 8.29 7.75 (lb/100 ft²

FIGS. 9(b) and (c) compare the effect of temperature on pressuresobserved with two different fluid weights (12.1 and 12.4 ppg) whenapplying six different and increasing shear rates (2, 6, 100, 200, 300,and 600 rpm). Two common testing temperatures were used—40 and 120degrees Fahrenheit. The change in temperature and fluid weight resultedin minimal change in fluid behavior. FIG. 9(a) compares the yield pointof two different weight formulations (12.1 pounds per gallon and 12.4pounds per gallon) of a fluid of the present invention at two differenttemperatures (40 degrees Fahrenheit and 120 degrees Fahrenheit). Theyield point is unexpectedly lower at 40 degrees than at 120 degrees.Prior art oil-based fluids typically have lower yield points at highertemperatures, as traditional or prior art oils tend to thin or havereduced viscosity as temperatures increase. In contrast, the fluid ofthe invention can be thinned at lower temperatures without significantlyaffecting the viscosity of the fluid at higher temperatures. Thisfeature or characteristic of the invention is a further indicator thatthe invention will provide good performance as a drilling fluid and willprovide low ECDs. Moreover, this characteristic indicates the ability ofthe fluid to maintain viscosity at higher temperatures.

FIG. 10 compares the viscosity of a base fluid for comprising a drillingfluid of the present invention with known base fluids of some prior artinvert emulsion drilling fluids. The base fluid for the drilling fluidof the present invention is one of the thickest or most viscous. Yetwhen comprising a drilling fluid of the invention, the drilling fluidhas low ECDs, provides good suspension of drill cuttings, satisfactoryparticle plugging and minimal fluid loss in use. Such surprisingadvantages of the drilling fluids of the invention are believed to befacilitated in part by a synergy or compatibility of the base fluid withappropriate thinners for the fluid.

Thinners disclosed in International Patent Application Nos.PCT/US00/35609 and PCT/US00/35610 of Halliburton Energy Services, Inc.,Cognis Deutschland GmbH & Co KG., Heinz Muller, Jeff Kirsner(co-inventor of the present invention) and Kimberly Burrows (co-inventorof the present invention), both filed Dec. 29, 2000 and entitled“Thinners for Invert Emulsions,” and both incorporated herein byreference, are particularly useful in the present invention foreffecting such “selective thinning” of the fluid of the presentinvention; that is thinning at lower temperatures without rendering thefluid too thin at higher temperatures. Such thinners may have thefollowing general formula: R—(C₂H₄O)_(n)(C₃H₆O)_(m)(C₄H₈O)_(k)—H(“formula I”), where R is a saturated or unsaturated, linear or branchedalkyl radical having about 8 to about 24 carbon atoms, n is a numberranging from about 1 to about 10, m is a number ranging from about 0 toabout 10, and k is a number ranging from about 0 to about 10.Preferably, R has about 8 to about 18 carbon atoms; more preferably, Rhas about 12 to about 18 carbon atoms; and most preferably, R has about12 to about 14 carbon atoms. Also, most preferably, R is saturated andlinear.

The thinner may be added to the drilling fluid during initialpreparation of the fluid or later as the fluid is being used fordrilling or well service purposes in the formation. The quantity addedis an effective amount to maintain or effect the desired viscosity ofthe drilling fluid. For purposes of this invention, an “effectiveamount” of thinner of formula (I) is preferably from about 0.5 to about15 pounds per barrel of drilling fluid or mud. A more preferred amountof thinner ranges from about 1 to about 5 pounds per barrel of drillingfluid and a most preferred amount is about 1.5 to about 3 pounds thinnerper barrel of drilling fluid.

The compositions or compounds of formula (I) may be prepared bycustomary techniques of alkoxylation, such as alkoxylating thecorresponding fatty alcohols with ethylene oxide and/or propylene oxideor butylene oxide under pressure and in the presence of acidic oralkaline catalysts as is known in the art. Such alkoxylation may takeplace blockwise, i.e., the fatty alcohol may be reacted first withethylene oxide, propylene oxide or butylene oxide and subsequently, ifdesired, with one or more of the other alkylene oxides. Alternatively,such alkoxylation may be conducted randomly, in which any desiredmixture of ethylene oxide, propylene oxide and/or butylene oxide isreacted with the fatty alcohol.

In formula (I), the subscripts n and m respectively represent the numberof ethylene oxide (EO) and propylene oxide (PO) molecules or groups inone molecule of the alkoxylated fatty alcohol. The subscript k indicatesthe number of butylene oxide (BO) molecules or groups. The subscripts n,m, and k need not be integers, since they indicate in each casestatistical averages of the alkoxylation. Included without limitationare those compounds of the formula (I) whose ethoxy, propoxy, and/orbutoxy group distribution is very narrow, such as for example, “narrowrange ethoxylates” also called “NREs” by those skilled in the art.

To accomplish the purposes of this invention, the compound of formula(I) must contain at least one ethoxy group. Preferably, the compound offormula I will also contain at least one propoxy group (C₃H₆O—) orbutoxy group (C₄H₈O—). Mixed alkoxides containing all three alkoxidegroups—ethylene oxide, propylene oxide, and butylene oxide—are possiblefor the invention but are not preferred.

Preferably, for use according to this invention, the compound of formula(I) will have a value for m ranging from about 1 to about 10 with k zeroor a value for k ranging from about 1 to about 10 with m zero. Mostpreferably, m will be about 1 to about 10 and k will be zero.

Alternatively, such thinners may be a non-ionic surfactant which is areaction product of ethylene oxide, propylene oxide and/or butyleneoxide with C₁₀₋₂₂ carboxylic acids or C₁₀₋₂₂ carboxylic acid derivativescontaining at least one double bond in position 9/10 and/or 13/14 havingunits of the general formula:

(“formula II”) where R₁ is a hydrogen atom or an OH group or a groupOR₂, where R₂ is an alkyl group of about 1 to about 18 carbon atoms, oran alkenyl group of about 2 to about 18 carbon atoms or a group of theformula:

where R₃ is a hydrogen atom, or an alkyl group of about 1 to about 21carbon atoms or an alkylene group of about 2 to about 21 carbon atoms. Aformula (II) thinner may be used alone or may be used in combinationwith a formula (I) thinner or co-thinner.

Preferred commercially available thinners include, for example, productshaving the tradenames COLDTROL® (alcohol derivative), OMC2™ (oligomericfatty acid), ATC® (modified fatty acid ester), to be used alone or incombination, and available from Halliburton Energy Services, Inc. inHouston, Tex.

The formulations of the fluids of the invention, and also theformulations of the prior art isomerized olefin based drilling fluids,used in drilling the boreholes cited in the data above, vary with theparticular requirements of the subterranean formation. Table 3 below,however, provides example formulations and properties for these twotypes of fluids discussed in the field data above. All trademarkedproducts in Table 3 are available from Halliburton Energy Services, Inc.in Houston, Tex., including: LE MUL™ emulsion stabilizer (a blend ofoxidized tall oil and polyaminated fatty acid); LE SUPERMUL™ emulsifier(polyaminated fatty acid); DURATONE® HT filtration control agent(organophilic leonardite); ADAPTA® HP filtration control agent(copolymer particularly suited for providing HPHT filtration control innon-aqueous fluid systems); RHEMOD L™ suspension agent/viscosifier(modified fatty acid); GELTONE® II viscosifier (organophilic clay);VIS-PLUS® suspension agent (carboxylic acid); BAROID® weighting agent(ground barium sulfate); and DEEP-TREAT® wetting agent/thinner(sulfonate sodium salt). In determining the properties in Table 3,samples of the fluids were sheared in a Silverson commercial blender at7,000 rpm for 10 minutes, rolled at 150 degrees Fahrenheit for 16 hours,and stirred for 10 minutes. Measurements were taken with the fluids at120 degrees Fahrenheit, except where indicated otherwise. TABLE 3Example Formulations Isomerized Olefin ACCOLADE ™ Based Invert EmulsionFluids and Compounds System Drilling Fluid ACCOLADE ™ Base (bbl) 0.590 —SF ™ Base (bbl) — 0.568 LE MUL ™ ¹ (lb) — 4 LE SUPERMUL ™ ² (lb) 10 6Lime (lb) 1 4 DURATONE ® HT ³ (lb) — 4 Freshwater (bbl) 0.263 0.254ADAPTA ® HP ⁴ (lb) 2 — RHEMOD L ™ ⁵ (lb) 1 — GELTONE ® II ⁶ (lb) — 5VIS-PLUS ® ⁷ (lb) — 1.5 BAROID ® ⁸ (lb) 138 138 Calcium chloride (lb) 3231 DEEP-TREAT ® ⁹ (lb) — 2 zebra zebra zebra B. Properties IsomerizedOlefin ACCOLADE ™ Based Invert Emulsion zebra System Drilling FluidPlastic Viscosity (cP) 19 19 Yield Point (lb/100 ft²) 13 14 10 secondgel (lb/100 ft²) 9 7 10 minute gel (lb/100 ft²) 12 9 HPHT Temperature (°F.) 225 200 HPHT @ 500 psid (mL) 0.8 1.2 Electrical stability (volts)185 380 Fann ™ Dial Readings: 600 rpm 51 52 300 rpm 32 33 200 rpm 25 26100 rpm 18 18  6 rpm 7 7  3 rpm 5 6¹ Blend of oxidized tall oil and polyaminated fatty acid emulsionstabilizer.² Polyaminated fatty acid emulsifier.³ Organophilic leonardite filtration control agent.⁴ Copolymer HTHP filtration control agent for non-aqueous systems.⁵ Modified fatty acid suspension agent/viscosifier.⁶ Organophilic clay viscosifier.⁷ Carboxylic acid suspension agent.⁸ Ground barium sulfate weighting agent.⁹ Sulfonate sodium salt wetting agent/thinner.

The present invention is directed to using invert emulsion baseddrilling fluids that contain fragile gels or exhibit fragile gelbehavior in drilling operations, such as drilling, running casing, andcementing. The present invention is also directed to reducing the lossof drilling fluids or drilling muds during such drilling operations byemploying invert emulsion based drilling fluids that contain fragilegels or exhibit fragile gel behavior, and that preferably provide lowECDs.

The invert emulsion drilling fluids of the present invention have aninvert emulsion base. This base is not limited to a single formulation.Test data discussed above is from example invert emulsion drillingfluids of the invention comprising a blend of one or more esters and oneor more isomerized, or internal, olefins (“ester blend”) such asdescribed in U.S. patent application Ser. No. 09/929,465, of JeffKirsner (co-inventor of the present invention), Kenneth W. Pober andRobert W. Pike, filed Aug. 14, 2001, entitled “Blends of Esters withIsomerized Olefins and Other Hydrocarbons as Base Oils for InvertEmulsion Oil Muds,” incorporated herein by reference. In such blend,preferably the esters will comprise at least about 10 weight percent ofthe blend and may comprise up to about 99 weight percent of the blend,although the esters may be used in any quantity. Preferred esters forblending are comprised of about C₆ to about C₁₄ fatty acids andalcohols, and are particularly or more preferably disclosed in U.S. Pat.No. Re. 36,066, reissued Jan. 25, 1999 as a reissue of U.S. Pat. No.5,232,910, assigned to Henkel KgaA of Dusseldorf, Germany, and BaroidLimited of London, England, and in U.S. Pat. No. 5,252,554, issued Oct.12, 1993, and assigned to Henkel Kommanditgesellschaft auf Aktien ofDusseldorf, Germany and Baroid Limited of Aberdeen, Scotland. Estersdisclosed in U.S. Pat. No. 5,106,516, issued Apr. 21, 1992, and U.S.Pat. No. 5,318,954, issued Jun. 7, 1984, both assigned to HenkelKommanditgesellschaft auf Aktien, of Dusseldorf, Germany, may also beused. The most preferred esters for use in the invention are comprisedof about C₁₂ to about C₁₄ fatty acids and 2-ethyl hexanol or about C₈fatty acids and 2-ethyl hexanol. These most preferred esters areavailable commercially under tradenames PETROFREE® and PETROFREE LV™,respectively, from Halliburton Energy Services, Inc. in Houston, Tex.Although esters made with fatty acids and alcohols are preferred, estersmade other ways, such as from combining olefins with either fatty acidsor alcohols, may also be effective.

Isomerized, or internal, olefins for blending with the esters for anester blend may be any such olefins, straight chain, branched, orcyclic, preferably having about 10 to about 30 carbon atoms. Isomerized,or internal, olefins having about 40 to about 70 weight percent C₁₆ andabout 20 to about 50 weight percent C₁₈ are especially preferred. Anexample of an isomerized olefin for use in an ester blend in theinvention that is commercially available is SF™ Base fluid, availablefrom Halliburton Energy Services, Inc. in Houston, Tex. Alternatively,other hydrocarbons such as paraffins, mineral oils, glyceride triesters,or combinations thereof may be substituted for or added to the olefinsin the ester blend. Such other hydrocarbons may comprise from about 1weight percent to about 99 weight percent of such blend.

Invert emulsion drilling fluids may be prepared comprising SF™ Basewithout the ester, however, such fluids are not believed to provide thesuperior properties of fluids of the invention with the ester. Fielddata discussed above has demonstrated that the fluids of the inventionare superior to prior art isomerized olefin based drilling fluids, andthe fluids of the invention have properties especially advantageous insubterranean wells drilled in deep water. Moreover, it is believed thatthe principles of the method of the invention may be used with invertemulsion drilling fluids that form fragile gels or yield fragile gelbehavior, provide low ECDs, and have (or seem to have) viscoelasticitythat may not be comprised of an ester blend. One example of such a fluidmay comprise a polar solvent instead of an ester blend.

Other examples of possible suitable invert emulsion bases for thedrilling fluids of the present invention include isomerized olefinsblended with other hydrocarbons such as linear alpha olefins, paraffins,or naphthenes, or combinations thereof (“hydrocarbon blends”).

Paraffins for use in blends comprising invert emulsions for drillingfluids for the present invention may be linear, branched, poly-branched,cyclic, or isoparaffins, preferably having about 10 to about 30 carbonatoms. When blended with esters or other hydrocarbons such as isomerizedolefins, linear alpha olefins, or naphthenes in the invention, theparaffins should comprise at least about 1 weight percent to about 99weight percent of the blend, but preferably less than about 50 weightpercent. An example of a commercially available paraffin suited forblends useful in the invention is called tradename XP-07™, availablefrom Halliburton Energy Services, Inc. in Houston, Tex. XP-07™ isprimarily a C₁₂₋₁₆ linear paraffin.

Examples of glyceride triesters for ester/hydrocarbon blends useful inblends comprising invert emulsions for drilling fluids for the presentinvention may include without limitation materials such as rapeseed oil,olive oil, canola oil, castor oil, coconut oil, corn oil, cottonseedoil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perillaoil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil,and sunflower oil.

Naphthenes or napthenic hydrocarbons for use in blends comprising invertemulsions for drilling fluids for the present invention may be anysaturated, cycloparaffinic compound, composition or material with achemical formula of C_(n)H₂, where n is a number about 5 to about 30.

In still another embodiment, a hydrocarbon blend might be blended withan ester blend to comprise an invert emulsion base for a drilling fluidof the present invention.

The exact proportions of the components comprising an ester blend (orother blend or base for an invert emulsion) for use in the presentinvention will vary depending on drilling requirements (andcharacteristics needed for the blend or base to meet thoserequirements), supply and availability of the components, cost of thecomponents, and characteristics of the blend or base necessary to meetenvironmental regulations or environmental acceptance. The manufactureof the various components of the ester blend (or other invert emulsionbase) will be understood by one skilled in the art.

Further, the invert emulsion drilling fluid of the invention or for usein the present invention has added to it or mixed with the invertemulsion base, other fluids or materials needed to comprise a completedrilling fluid. Such materials may include for example additives toreduce or control temperature rheology or to provide thinning, such as,for example, additives having the tradenames COLDTROL®, RHEMOD L™, ATC®,and OMC2™; additives for providing temporary increased viscosity forshipping (transport to the well site) and for use in sweeps, such as,for example an additive having the tradename TEMPERUS™ (modified fattyacid); additives for filtration control, such as, for example additiveshaving the tradename ADAPTA HP®; additives for high temperature highpressure control (HTHP) and emulsion stability, such as, for example,additives having the tradename FACTANT™ (highly concentrated tall oilderivative); and additives for emulsification, such as, for exampleadditives having the tradename LE SUPERMUL™ (polyaminated fatty acid).Blends of thinners such as the OMC2™, COLDTROL®, and ATC® thinners canbe more effective in fluids of the invention than a single one of thesethinners. All of the aforementioned trademarked products are availablefrom Halliburton Energy Services, Inc. in Houston, Tex., U.S.A.

The invert emulsion drilling fluid of the present invention preferablydoes not have added to it any organophilic clays. The fluid of theinvention does not need organophilic clay or organophilic lignites toprovide it needed viscosity, suspension characteristics, or filtrationcontrol to carry drill cuttings to the well surface. Moreover, the lackof organophilic clays and organophilic lignites in the fluid is believedto enhance the tolerance of the fluid to the drill cuttings. That is,the lack of organophilic clays and organophilic lignites in the fluid ofthe invention is believed to enable the fluid to suspend and carry drillcuttings without significant change in the fluid's rheologicalproperties.

The foregoing description of the invention is intended to be adescription of preferred embodiments. Various changes in the details ofthe described fluids and method of use can be made without departingfrom the intended scope of this invention as defined by the appendedclaims.

1. A method of preparing a drilling fluid comprising formulating aninvert emulsion drilling fluid that, when used in drilling, suspendsweighting agent and/or drill cuttings when stresses or forces associatedwith drilling are reduced or removed from the drilling fluid, andproduces substantially no pressure spike upon resumed stopped drillingas detected by pressure-while-drilling equipment or instruments.
 2. Themethod of claim 1 wherein the drilling fluid comprises: a continuousphase comprising at least one component selected from the groupconsisting of: olefins, paraffin hydrocarbons, esters, mineral oilhydrocarbons, glyceride triesters, and naphthenic hydrocarbons; and aninternal phase comprising water.
 3. The method of claim 2 wherein thedrilling fluid further comprises a modified fatty acid rheology modifiercomprising dimeric and trimeric fatty acids.
 4. The method of claim 3wherein the drilling fluid further comprises a copolymer filtrationcontrol agent.
 5. The method of claim 1 wherein the drilling fluid isfree of organophilic clay.
 6. The method of claim 1 wherein the drillingfluid is substantially free of lignite.
 7. The method of claim 1 whereinthe drilling fluid is free of organophilic clay and lignite.
 8. Thedrilling fluid of claim 1 wherein the drilling fluid is free of anorganophilic filtration control agent.
 9. A method for preparing adrilling fluid comprising formulating a drilling fluid comprising aninvert emulsion base comprising an ester blend and further comprising athinner compatible with said ester blend such that said fluid builds astructure at rest capable of suspending drill cuttings withoutappreciable sag and wherein said structure may be immediately disruptedby movement of said fluid without registering an appreciable pressurespike with pressure-while-drilling equipment.
 10. A method of drillingin a subterranean formation comprising the steps of: providing an invertemulsion drilling fluid, the drilling fluid comprising: a continuousphase comprising at least one component selected from the groupconsisting of: paraffin hydrocarbons, esters, linear alpha olefins,mineral oil hydrocarbons, glyceride triesters, and naphthenichydrocarbons, an internal phase comprising water, an emulsifier, aweighting agent, a modified fatty acid rheology modifier comprisingdimeric and trimeric fatty acids, and a copolymer filtration controlagent, wherein the drilling fluid: suspends the weighting agent and/ordrill cuttings when stresses or forces associated with the drilling arereduced or removed from the drilling fluid; and produces substantiallyno pressure spike upon resumed stopped drilling, as detected bypressure-while-drilling equipment or instruments; and drilling in thesubterranean formation with the drilling fluid.
 11. The method of claim10 wherein the drilling fluid is exposed to temperatures in a range offrom about 40° F. to about 120° F.
 12. The method of claim 10 whereinthe drilling fluid has a lower yield point at a temperature of about 40°F. than at a temperature of about 120° F.
 13. The method of claim 10wherein an equivalent circulating density of the drilling fluidapproximates a surface density of the drilling fluid.
 14. The method ofclaim 10 wherein the drilling is performed offshore.
 15. The method ofclaim 10 wherein the drilling fluid is tolerant to drill cuttings. 16.The method of claim 10 wherein the drilling fluid does not exhibitsignificant sag when at rest.
 17. The method of claim 10 wherein thedrilling features a drilling fluid loss of less than about 1 barrel perbarrel of hole drilled.
 18. The method of claim 10 further comprisingrunning casing and/or cementing a wellbore in the subterraneanformation.
 19. The method of claim 18 wherein loss of the drilling fluidis less than about 100 barrels of total drilling fluid when runningcasing and/or cementing.
 20. The method of claim 18 wherein loss of thedrilling fluid is less than about 500 barrels of total drilling fluidduring drilling, running casing and cementing.
 21. The method of claim10 wherein the drilling fluid further comprises a thinner.
 22. Themethod of claim 10 wherein the drilling fluid further comprises athinner that reduces the viscosity of the drilling fluid at about 40° F.to a greater extent than it reduces the viscosity of the drilling fluidat about 120° F.
 23. The method of claim 10 wherein the drilling fluidfurther comprises one or more additives selected from the groupconsisting of: an emulsion stabilizer, a viscosifier, an HTHP additive,and a water activity lowering material.
 24. The method of claim 10wherein the drilling is drilling a wellbore in the subterraneanformation at a water depth greater than about 1,500 feet.
 25. The methodof claim 10 wherein the drilling fluid is free of organophilic clay. 26.The method of claim 10 wherein the drilling fluid is substantially freeof lignite.
 27. The method of claim 10 wherein the drilling fluid isfree of organophilic clay and lignite.
 28. The drilling fluid of claim10 wherein the drilling fluid is free of an organophilic filtrationcontrol agent.
 29. An invert emulsion drilling fluid for use in drillingin a subterranean formation comprising: a continuous phase comprising atleast one component selected from the group consisting of: paraffinhydrocarbons, esters, linear alpha olefins, mineral oil hydrocarbons,glyceride triesters, and naphthenic hydrocarbons, an internal phasecomprising water, an emulsifier, a weighting agent, a modified fattyacid rheology modifier comprising dimeric and trimeric fatty acids, anda copolymer filtration control agent, wherein the drilling fluid:suspends the weighting agent and/or drill cuttings when stresses orforces associated with the drilling are reduced or removed from thedrilling fluid; and produces substantially no pressure spike uponresumed stopped drilling, as detected by pressure-while-drillingequipment or instruments.
 30. The drilling fluid of claim 29 wherein thedrilling fluid is exposed to temperatures in a range of from about 40°F. to about 120° F.
 31. The drilling fluid of claim 29 wherein thedrilling fluid has a lower yield point at a temperature of about 40° F.than at a temperature of about 120° F.
 32. The drilling fluid of claim29 wherein an equivalent circulating density of the drilling fluidapproximates a surface density of the drilling fluid.
 33. The drillingfluid of claim 29 wherein the drilling is performed offshore.
 34. Thedrilling fluid of claim 29 wherein the drilling is performed in awellbore in the subterranean formation at a water depth greater thanabout 1,500 feet.
 35. The drilling fluid of claim 29 wherein thedrilling fluid is tolerant to drill cuttings.
 36. The drilling fluid ofclaim 29 wherein the drilling fluid does not exhibit significant sagwhen at rest.
 37. The drilling fluid of claim 29 wherein loss of thedrilling fluid is less than about 1 barrel per barrel of hole drilledwhen drilling a wellbore in the subterranean formation.
 38. The drillingfluid of claim 29 wherein loss of the drilling fluid is less than about100 barrels of total drilling fluid when running casing and/or cementinga wellbore in the subterranean formation.
 39. The drilling fluid ofclaim 29 wherein loss of the drilling fluid is less than about 500barrels of total drilling fluid when drilling, running casing andcementing a wellbore in the subterranean formation.
 40. The drillingfluid of claim 29 wherein the drilling fluid further comprises athinner.
 41. The drilling fluid of claim 29 wherein the drilling fluidfurther comprises a thinner that reduces the viscosity of the drillingfluid at about 40° F. to a greater extent than it reduces the viscosityof the drilling fluid at about 120° F.
 42. The drilling fluid of claim29 wherein the drilling fluid further comprises one or more additivesselected from the group consisting of: an emulsion stabilizer, aviscosifier, an HTHP additive, and a water activity lowering material.43. The drilling fluid of claim 29 wherein the drilling fluid is free oforganophilic clay.
 44. The drilling fluid of claim 29 wherein thedrilling fluid is substantially free of lignite.
 45. The drilling fluidof claim 29 wherein the drilling fluid is free of organophilic clay andlignite.
 46. The drilling fluid of claim 29 wherein the drilling fluidis free of an organophilic filtration control agent.